In rotary drilling of subterranean wells, a drilling fluid having the desired fluid properties travels through the drill pipe, out a nozzle at the drill bit, and returns to the surface through an annular portion of the wellbore. Drilling fluids are carefully formulated to impart numerous functions and possess fluid characteristics that optimize production while not presenting a risk to personnel, drilling equipment, or the environment. A drilling fluid should circulate throughout the well and carry cuttings from beneath the bit, transport the cuttings up the annulus, and allow their separation at the surface. At the same time, the drilling fluid is expected to lubricate, cool and clean the drill bit, reduce friction between the drill string and the sides of the borehole, maintain stability in the borehole's encased sections, and prevent the unwanted influx of formation fluids from permeable rock formations penetrated by the bit.
Water-based drilling fluids, i.e., water-based muds, typically contain synthetic and natural polymers to establish the desired rheological properties of the drilling fluid. The drilling fluid is preferably formulated to exhibit a rheology that both enhances the suspension characteristics of the fluid for the removal of drill cuttings and also minimizes the pressure drop in the drillpipe. While the viscosity of the drilling fluid at high shear rates affects the pressure drop in the drillpipe and annulus, the viscosity of the drilling fluid at low shear rates influences the suspending and solids (i.e., weighting agents, drill cuttings) carrying capacity of the drilling fluid. Drilling fluid rheology at high shear rates is commonly referred to as the plastic viscosity (PV), or high shear rate viscosity, as defined by the Bingham plastic model (τ=PV(γ)+YP, wherein τ is the shear stress [force/area; lb/100 ft2] applied to the drilling fluid, and γ is the shear rate [time−1]). Rheology at low shear rates is often characterized by the yield point (YP), also referred to as the low shear rate viscosity, as defined by the Bingham model. The Bingham model is widely employed to describe fluid flow in the drilling fluids industry.
It is important that the driller or operator of subterranean wells be able to control the rheological properties of water-based drilling fluids during the use of these fluids in drilling operations. In one aspect, the pH of water-based drilling fluids is typically maintained in the range from about 7.5 to about 12, and preferably in the range from about 9 to about 11, in order to retard uncontrolled polymer degradation and help maintain the rheological properties of the drilling fluid. The pH can be adjusted by methods known to those skilled in the art, including the addition of bases to the drilling fluid. Suitable bases include potassium hydroxide, sodium hydroxide, sodium carbonate (soda ash), magnesium oxide, calcium hydroxide and zinc oxide. In another aspect, sometimes the operator needs to reduce the viscosity of the drilling fluid in order to allow, for example, casing to be run or to bring the drilling fluid back into specification after a build-up of drill solids or weighting-up has occurred. Normally the reduction in viscosity of water-based drilling fluids is achieved by dilution with water which modifies the relative concentrations of mud components and thus subsequently requires post-dilution treatment of the drilling fluid and disposal of excess fluid. Post-dilution treatment of drilling fluids, particularly high performance water-based muds (HPWBMs) containing a number of additives, can significantly increase the cost to the operator who desires to reduce the viscosity of the drilling fluid.
It would be an improvement in the art to provide an alternative method to reduce the viscosity of water-based muds in a controlled manner without requiring dilution.